Drilling for oil and gas is an expensive, high-risk business, even when the drilling is carried out in a proven field. Petroleum development and production must be sufficiently profitable over the long term to withstand a variety of economic uncertainties. Multiphase pumping is increasingly being used to aid in the production of wellhead fluids. Both surface and subsea installations of these pumps are increasing well production. Multiphase pumps are particularly helpful in producing remote fields and many companies are considering their use for producing remote pockets of oil and for producing deep water reservoirs from shallower water facilities. These pumps allow producers to transport wellhead fluids (oil, water, and gas) to distant processing facilities (instead of building new processing facilities near the wellheads). These pumps also allow lower final reservoir pressures before abandoning production and consequently a greater total recovery from the reservoir.
For deep water reservoirs, producers are very interested in using multiphase pumps to transport wellhead fluids from deep waters to shallow water processing facilities. While there are a number of technical difficulties in this type of production, the cost savings are very large. To build processing facilities over reservoirs in waters 6,000 to 10,000 feet deep cost tens of billions of dollars, as compared to a cost of hundreds of millions of dollars to build such facilities in moderate water depths of 400 to 600 feet. Consequently, producers would like to transport wellhead fluids from the sea-floor in deep waters through pipelines to processing facilities in moderate water depths.
Currently, transport distances of 30 to 60 miles are being considered. In many locations around the world, a 30 to 60 mile reach from the edge of the continental shelf into deeper waters significantly increases the number of oil reservoirs which could be produced. In the Gulf of Mexico, for example, such a reach typically goes to water depths of 6,000 feet and deeper. In the near future, greater reaches up to 100 miles are envisioned. Multiphase pumps are a design being considered for supplying the pressure boost required for this long-distance transport of wellhead fluids. They are typically connected at one end to a Christmas tree manifold, whose casing head is attached to the top of wells from which fluids flow as a result of indigenous reservoir energy, and at the other end to a pipeline which transports the fluids to the remote processing site.
Wellhead fluids can exhibit a wide range of chemical and physical properties. These wellhead fluid properties can differ from zone to zone within a given field and can change with time over the course of a well's life. Furthermore, well bore flow exhibits a well-known array of flow regimes including slug flow, bubble flow, stratified flow, and annular mist, depending on flow velocity, geometry, and the aforementioned fluid properties. Consequently, the ideal multiphase pump should allow for a broad range of input and output parameters without unduly compromising pumping efficiency and service life.
Pumping gas-entrained liquids of varying gas content presents a difficult design problem. Some pumps that have been used include twin-screw pumps, helico-axial pumps, counter-rotating axial-flow pumps, piston pumps, and diaphragm pumps. Twin-screw pumps are one of the favored types of pump for handling the wide range of liquid/gas ratios found in wellhead fluids. Nevertheless, this type of pump has its detractors. For example, one well-known problem for twin-screw pumps is pump seizing.
A twin-screw pump has two rotors that rotate in a close-fitting casing (rotor enclosure). For a given inlet volumetric rate, gas fraction increases result in mass rate reductions, decreases in the thermal transport capacity of the pumped fluids, and temperature elevations in the pump. Consequently, at high pressure boosts, for a given set of operating conditions, a critical gas fraction exists. Pumping at gas fractions greater than the critical gas fraction will result in excessive heating of the pump rotors causing an expansion of the rotors such that the rotors will interfere with the pump body (rotor enclosure) causing the pump to seize.
In typical oil field applications, the gas fraction (or percentage of gas content of the wellhead fluid by volume at inlet conditions) is required to be less than some upper limit for a given pump pressure boost. This limit is typically around 95 to 97% gas fraction for pressure boosts of around 900 psi. In order to ensure that wellhead fluids do not exceed this requirement, several approaches have been taken including: (1) buffer tanks have been added upstream of the pump to dampen excessive gas/liquid ratio variations, (2) liquids from the pump outlet or other liquids are commingled with the inlet stream to reduce the inlet gas fraction, or (3) combinations of 1 and 2 are used to reduce the inlet gas fraction. Method 1 extends the operational range of the pump marginally, and methods 2 and 3 extend the operating range a little more but are extremely inefficient. Even with these approaches, pump seizing may still occur.
Therefore, there is a need for an efficient means of cooling the pump rotors to prevent the excessive heat buildup that occurs when the pump encounters fluids having high gas fractions.